Directional control has become increasingly important in the drilling of subterranean oil and gas wells, for example, to more fully exploit hydrocarbon reservoirs. Two-dimensional and three-dimensional rotary steerable tools are used in many drilling applications to control the direction of drilling. Such steering tools commonly include a plurality of force application members (also referred to herein as blades) that may be independently extended out from and retracted into a housing. The blades are disposed to extend outward from the housing into contact with the borehole wall and to thereby displace the housing from the centerline of a borehole during drilling. The housing is typically deployed about a shaft, which is coupled to the drill string and disposed to transfer weight and torque from the surface (or from a mud motor) through the steering tool to the drill bit assembly.
It is well known in the art that severe dynamic conditions are often encountered during drilling. Commonly encountered dynamic conditions include, for example, bit bounce, lateral shock and vibration, and stick/slip. Bit bounce includes axial vibration of the drill string, often resulting in temporary lift off of the drill bit from the formation (“bouncing” of the drill bit off the bottom of the borehole). Bit bounce is known to reduce the rate of penetration (ROP) during drilling, cause excessive fatigue damage to BHA components, and may even damage the well in extreme conditions. Lateral vibrations are those which are transverse to the axis of the drill string. Such lateral vibrations are commonly recognized as the leading cause of drill string and BHA failures and may be caused, for example, by bit whirl and/or the use of unbalanced drill string components. Stick/slip refers to a tensional vibration induced by friction between drill string components and the borehole wall. Stick/slip is known to produce instantaneous drill string rotation speeds many times that of the nominal rotation speed of the table. In stick/slip conditions a portion of the drill string or bit sticks to the borehole wall due to frictional forces often causing the drill string to temporarily stop rotating. Meanwhile, the rotary table continues to turn resulting in an accumulation of tensional energy in the drill string. When the tensional energy exceeds the static friction between the drill string and the borehole, the energy is released suddenly in a rapid burst of drill string rotation. Instantaneous downhole rotation rotates have been reported to exceed four times that of the rotary table. Stick/slip is known to cause severe damage to downhole tools, as well as connection fatigue, and excess wear to the drill bit and near-bit stabilizer blades. Such wear commonly results in reduced ROP and loss of steer ability in deviated boreholes. These harmful dynamic conditions not only cause premature failure and excessive wear of the drilling components, but also often result in costly trips (tripping-in and tripping-out of the borehole) due to unexpected tool failures and wear. Furthermore, there is a trend in the industry towards drilling deeper, smaller diameter wells where stick/slip becomes increasingly problematic. Problems associated with premature tool failure and wear are exacerbated (and more expensive) in such wells.
The above-described downhole dynamic conditions are known to be influenced by drilling conditions. By controlling such drilling conditions an operator can sometimes mitigate against damaging dynamic conditions. For example, bit bounce and lateral vibration conditions can sometimes be overcome by reducing both the weight on bit and the drill string rotation rate. Stick/slip conditions can often be overcome via increasing the drill string rotation rate and reducing weight on bit. The use of less aggressive drill bits also tends to reduce bit bounce, lateral vibrations, and stick/slip in many types of formations. The use of stiffer drill string components is further known to sometimes reduce stick/slip. While the damaging dynamic conditions may often be mitigated as described above, reliable measurement and identification of such dynamic conditions can be problematic. For example, lateral vibration and stick/slip conditions are not easily quantified by surface measurements. In fact, such dynamic conditions are sometimes not even detectable at the surface, especially at vibration frequencies above about 5 hertz.
Downhole dynamics measurement systems have been known in the art for at least 15 years. For example, U.S. Pat. No. 4,958,125 to Jardine et al discloses an accelerometer-based method for measuring the centripetal acceleration of a drill string in a borehole, and thereby determining instantaneous rotation rates of the drill string. More recently, U.S. Pat. No. 6,518,756 to Morys et al discloses a system and apparatus for determining the lateral velocity of a drill string within a borehole. While these, and other known systems and methods, may be serviceable in certain applications, there is yet need for further improvement. For example, the above-described methods each require at least four accelerometers deployed about the periphery of the drill string (Morys et al also requires the deployment of two additional magnetometers). The use of such dedicated sensors tends to increase costs and expend valuable BHA real estate (e.g., via the introduction of a dedicated sub). Also, such dedicated sensors tend to increase power consumption and component counts and, therefore, the complexity of MWD, LWD, and directional drilling tools, and thus tend to reduce reliability of the system. Moreover, dedicated sensors must typically be deployed a significant distance above the drill bit.
Therefore there exists a need for an improved apparatus and method for making downhole dynamics measurements. In particular, there exists a need for a rotary steerable deployment of such a dynamics measurement system and method.